Organic acid-based enhanced waterflooding

ABSTRACT

In an embodiment, a hydrocarbon recovery material includes an organic acid and a water material, the organic acid including a naphthenic acid, L-prolific, or a combination thereof. In another embodiment, an oil recovery method includes injecting a treatment fluid into a reservoir under reservoir conditions, the reservoir containing hydrocarbons, and the treatment fluid includes an organic acid and a water material. In another embodiment, an oil recovery method includes injecting a treatment fluid into a reservoir containing hydrocarbons, the treatment fluid comprising an organic acid in one or more of an oil-in-water emulsion, a resin dispersion, or a polymer capsule.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent ApplicationNo. 62/659,029, filed Apr. 17, 2018, the entirety of which is hereinincorporated by reference.

BACKGROUND Field

Embodiments of the present disclosure generally relate to methods forenhanced oil recovery. More specifically, embodiments described hereinrelate to organic acid-based enhanced waterflooding.

Description of the Related Art

Oil recovery is typically dictated by brine, oil, and rock interactions.Injection of low-salinity brine, regardless of whether the brine is theconnate or the injection water, has been shown to improve oil recoveryin sandstone reservoirs. Several mechanisms for this improvement havebeen suggested, but in large part, the observed wettability alterationtowards more water-wetness is credited for the enhancement in oilrecovery. Alteration of the rock surface wetting condition occurs as therock is exposed (e.g., aged) for extended periods of time (e.g., weeks)in the presence of high water saturation. Wettability alteration as amechanism for improved oil recovery has been investigated over theyears, yet no framework exists to date which fully explains allexperimental observations and improved materials for enhanced oilrecovery.

Water-in-oil emulsion's stability, another element in improved recovery,can be dictated by the formation of a viscoelastic interfacial film.Stable emulsions can be problematic because emulsions represent onespecies trapped in another, and therefore inhibit attempts to separateinto two individual phases. Viscoelasticity increases generallycorrelate with a delay in snap-off and an increase in emulsioncoalescence in porous media. Snap-off may be described as the separation(pinch off) of the oil phase into a droplet or oil ganglion during waterimbibition in a water-wet constriction. Emulsion coalescence andsnap-off delay are related to connectivity in the medium, which rendersa more mobilized fluid; however, challenges remain in forming amobilized fluid with improved connectivity.

Thus, what is needed in the art are improved methods and materials forenhanced oil recovery. More specifically, what is needed in the art arematerials and methods for organic acid-based waterflooding.

SUMMARY

In an embodiment, a hydrocarbon recovery material includes an organicacid and a water material, the organic acid including a naphthenic acid,L-proline, or a combination thereof.

In another embodiment, an oil recovery method includes injecting atreatment fluid into a reservoir under reservoir conditions, thereservoir containing hydrocarbons, and the treatment fluid includes anorganic acid and a water material.

In another embodiment, an oil recovery method includes injecting atreatment fluid into a reservoir containing hydrocarbons, the treatmentfluid comprising an organic acid in one or more of an oil-in-wateremulsion, a resin dispersion, or a polymer capsule.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentdisclosure can be understood in detail, a more particular description ofthe disclosure, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlyexemplary embodiments and are therefore not to be considered limiting ofits scope, may admit to other equally effective embodiments.

FIG. 1 shows 1D Proton Nuclear Magnetic Resonance (¹H NMR) spectra forexample acids described herein according to some embodiments.

FIG. 2A is concentration sweep data for example acids according to someembodiments.

FIG. 2B is concentration sweep data for example acids according to someembodiments.

FIG. 2C is concentration sweep data for example acids according to someembodiments.

FIG. 3A is rheology data (viscous modulus versus time) for example acidsanalyzed at a concentration of 1 milliMolar (mM) according to someembodiments.

FIG. 3B is rheology data (elastic modulus versus time) for example acidsanalyzed at a concentration of 1 mM according to some embodiments.

FIG. 3C is rheology data (tan(δ) versus time) for example acids analyzedat a concentration of 1 mM according to some embodiments.

FIG. 4A is rheology data (viscosity and elastic moduli versus time) foran example acid according to some embodiments.

FIG. 4B is the tangent of the phase angle versus time (tan(δ)) for anexample acid according to an embodiment.

FIG. 5 shows NMR data for NAmix1 according to some embodiments.

FIG. 6A shows density distribution functions for example acids at 1 mMconcentration on day 1 according to some embodiments.

FIG. 6B shows density distribution functions for example acids at 1 mMconcentration on day 14 according to some embodiments.

FIGS. 7A-7G show density distribution function as a function of dropletdiameter for the example acids at day 1, day 5, and day 14 according tosome embodiments.

FIG. 8A is an image of a bridge before aging or oil removal according tosome embodiments.

FIG. 8B is an image observed in an inelastic break of a bridge accordingto some embodiments.

FIG. 8C is an image observed in an elastic break of a bridge accordingto some embodiments.

FIG. 9A is an unaged bridge image of the 1% Na₂SO₄ in oil systemaccording to some embodiments.

FIG. 9B is an unaged bridge image of an example acidified brine in oilsystem according to some embodiments.

FIG. 9C is an unaged bridge image of an example acidified brine in oilsystem according to some embodiments.

FIG. 9D is an unaged bridge image of an example acidified brine in oilsystem according to some embodiments.

FIG. 10 shows the critical neck diameter (CND) to initial neck diameter(IND) for example acidified brine in oil systems as the systems ageaccording to some embodiments.

FIG. 11A shows the neck diameter (ND) to IND for example acidified brinein oil systems as the systems age according to some embodiments.

FIG. 11B is an image of the final frame of connection before the bridgefails of an example acidified brine in oil system according to someembodiments.

FIG. 11C is an image of the final frame of connection before the bridgefails of an example acidified brine in oil system according to someembodiments.

FIG. 11D is an image of the final frame of connection before the bridgefails of an example acidified brine in oil system according to someembodiments.

FIG. 12 is an image during bridge deflation for an example acidifiedbrine in oil system after 1 hour of aging according to some embodiments.

FIG. 13A shows the elastic modulus for example brine solutions in oil at25° C. according to some embodiments.

FIG. 13B shows the viscous modulus for example brine solutions in oil at25° C. according to some embodiments.

FIG. 13C shows the elastic modulus for example brine solutions in oil at80° C. according to some embodiments.

FIG. 13D shows the viscous modulus for example brine solutions in oil at80° C. according to some embodiments.

FIG. 14A shows the normalized elastic modulus after each interfacialtension (IFT) for example brine solutions in oil at 25° C. according tosome embodiments.

FIG. 14B shows the normalized viscous modulus after each IFT for examplebrine solutions in oil at 25° C. according to some embodiments.

FIG. 14C shows the normalized elastic modulus after each IFT for examplebrine solutions in oil at 80° C. according to some embodiments.

FIG. 14D shows the normalized viscous modulus after each IFT for examplebrine solutions in oil at 80° C. according to some embodiments.

FIG. 14E shows the tangent of the phase angle for example brinesolutions in oil at 25° C. according to some embodiments.

FIG. 14F shows the tangent of the phase angle for example brinesolutions in oil at 80° C. according to some embodiments.

FIG. 15A shows imbibition data for example acids in water-wet rockaccording to some embodiments.

FIG. 15B shows imbibition data for example acids in oil-wet rockaccording to some embodiments.

FIGS. 16A and 16B show viscoelasticity results for 1% Na2SO4 withchanging temperature according to some embodiments.

FIGS. 16C and 16D show viscoelasticity results for example acids withchanging temperature according to some embodiments.

FIGS. 16E and 16F show viscoelasticity results for example acids withchanging temperature according to some embodiments.

To facilitate understanding, identical reference numerals have beenused, where possible, to designate identical elements that are common tothe figures. It is contemplated that elements and features of oneembodiment may be beneficially incorporated in other embodiments withoutfurther recitation.

DETAILED DESCRIPTION

Embodiments described herein relate to organic acids, or the like, whichprovide for improved oil recovery. The inventors have surprisinglydiscovered that several organic acids (e.g., naphthenic acids,L-proline, etc.) are working at the interface to elicit an opportunisticinterfacial response. The possibility that acids could be beneficial ineliciting an interfacial response is surprising because acids aretypically associated with stabilizing emulsions and stable emulsionslead to less oil recovery. The structure of the organic acids is relatedto the interfacial rheological behavior of the system. Oil recovery canbe improved through manipulation of fluid-fluid interactions alone, andthe observed behavior for these organic acids is believed to enableutilization of various compounds for use in enhanced oil recovery (EOR).In some embodiments the interfacial response can be generated by one ormore organic acids (e.g., cyclopentane carboxylic acid, cyclohexanecarboxylic acid, 3-cyclohexane propionic acid, p-toluic acid, L-proline,a mixture of naphthenic acids, or a combination thereof).

In some embodiments, organic acids, such as various cycloalkanecarboxylic acids, are assessed for their ability to beneficially impactthe interface between oil and water; their impact on the stability ofemulsions and potential to delay snap-off is determined, as is theirimpact on the interfacial viscoelasticity. The cyclopentanesinvestigated showed a tendency to repair the interface after rupture,suggesting potential to regain connectivity in a reservoir after it hasbeen immobilized. In some embodiments, the enhanced oil recovery (EOR)materials described herein are utilized for destabilizing emulsions,maintaining mobilized fluid in the reservoir, and then re-establishingoil connectivity after it has been lost in reservoir. Various benefitsof the embodiments described herein include the low concentrations ofmaterial utilized to improve the probability of oil recovery. Theorganic acids can be directly dissolved in injection water forwaterflooding or delivered through encapsulation methods such assuspension in oil-in-water emulsions, resin dispersions, and polymerdelivery capsules, among other possibilities.

The structural trends described herein indicate that the branchedcyclohexane carboxylic acids can work to destabilize emulsions throughcoalescence and improved oil connectivity in porous media. Thestructural trends described herein also indicate that cyclopentanecarboxylic acids can repair the interface after rupture and can enablethe oil to regain connectivity in the reservoir. In addition, using acombination of different branched hydrocarbon compounds can elicitfluid-fluid behavior suggestive of improved connectivity and whichresults in improved recovery from the reservoir.

Methods described herein include various operations, which are performedeither alone or in combination, such as destabilizing emulsions andre-establishing connectivity after it has been lost. Low concentrationsof the organic acids, for example, less than 2 mM, such as about 1 mM,are utilized while providing for enhanced oil recovery. As a result,efficiency and economy of the oil recovery system can be increased.

The organic acids described herein can be directly dissolved at, e.g., aconcentration of two (2) milliMolar (mM) or lower in injection water forwaterflooding, or be delivered through encapsulation methods, such asdissolving the organic acids in oil-in-water emulsions at an oilfraction in water of 1-10 vol % at a concentration of organic acid of,e.g., up to about 200 mM in oil, resin dispersions extracted from thereservoir native crude oil at about the same vol % as oil-in-wateremulsions at a concentration of organic acid of, e.g., up to about 200mM in resin, and polymeric capsules at about the same vol % asoil-in-water emulsions at a concentration of organic acid in polymercapsules of, e.g., up to about 200 mM, among other possibilities. Incertain embodiments, the organic acids can be injected during secondaryor tertiary recovery operations. While not being bound by theory, it isbelieved that by implementing the embodiments described herein, anincremental recovery factor over traditional waterflooding is expectedto be 5% or higher, depending on the oil, water, and/or rock system, butit is believed to function advantageously in both elastic andnon-elastic reservoirs. Incremental recovery factor is the additionaloil recovered in tertiary mode, e.g., after the effectiveness oftraditional waterflooding ends.

Embodiments described herein include methods of enhanced oil recoveryfrom reservoirs that contain, e.g., hydrocarbons. According to someembodiments, a method for enhanced oil recovery includes an operation offorming a mixture (e.g., by dissolving) of one or more organic acids(e.g., any acid described herein such as cyclopentane carboxylic acid,L-proline, cyclohexane carboxylic acid, 3-cyclohexane propionic acid,p-toluic acid, other naphthenic acids (e.g., those acids having thegeneral formula C_(n)H_(2n-z)O₂ where n is the number of carbons and zis the unsaturation), or compounds with multiple carboxylic acid groups)in a water material (e.g., an injection water material) to form atreatment fluid. The concentration of organic acid in the treatmentfluid may about 100 mM or less, such as about 10 mM or less, such asfrom about 0.1 mM to about 10 mM, such as from about 0.2 mM to about 2mM, such as from about 0.5 mM to about 1 mM. The method can furtherinclude an operation of adding (e.g., injecting) the treatment fluidinto a reservoir containing hydrocarbons. The method may further includewithdrawing, removing, extracting, and/or producing hydrocarbons fromthe reservoir.

According to some embodiments, a method for enhanced oil recoveryincludes encapsulating one or more organic acids (e.g., any aciddescribed herein such as cyclopentane carboxylic acid, L-proline,cyclohexane carboxylic acid, 3-cyclohexane propionic acid, p-toluicacid, other naphthenic acids (e.g., those acids having the generalformula C_(n)H_(2n-z)O₂ where n is the number of carbons and z is theunsaturation), or compounds with multiple carboxylic acid groups) in oneor more of an oil-in-water emulsion, a resin dispersion, or a polymercapsule to form a treatment fluid. Encapsulating the organic acid in anoil-in-water emulsion may be performed by using about 1 vol % of any oilin water. The oil may be an oil produced or separated from producedemulsions. The organic acid can be mixed (e.g., dissolved) in the oil toform a first mixture having the organic acids at a concentration of,e.g., about 10,000 mM or less in oil (such as about 1,000 mM or less,such as about 200 mM or less). The first mixture may be added to avolume of water to make 100 vol % to create the oil-in-injection wateremulsions by using a shearing tool or ultrasonic dispersion tools.

Encapsulating the organic acid in a resin dispersion may be performed bytaking resin extracted from produced oil or an alternative crude oil anddissolving the organic acids at a concentration of, e.g., about 10,000mM or less in oil (such as about 1,000 mM or less, such as about 200 mMor less), and subsequently dispersing the acid-enriched resin in theinjection water to a desired concentration. Resins can be largepolymeric molecules that add to the viscosity of heavy oil, and crudeoil can include resins. Resins can be extracted by wet-chemistry (e.g.,by solvents) in a similar fashion to asphaltenes. Resins can aid indelivery methods as they can be soluble in the crude oil.

Encapsulating the organic acid in a polymer capsule may be performed bymixing (e.g., dissolving) organic acids in a polymer (such as apolyacrylamide, such as a 12-18 million Dalton polyacrylamide) alongwith a crosslinker (such as aluminum citrate) at, e.g., about 1:1 molarratio of crosslinker to polymer. The polymer capsule may then be addedto the injection water to form colloidal dispersions with the use oflow-shear mixing tools.

The final concentration of organic acid in the treatment fluid may beabout 100 mM or less, such as about 10 mM or less, such as from about0.1 mM to about 10 mM, such as from about 0.2 mM to about 2 mM, such asfrom about 0.5 mM to about 1 mM. The method may further includeinjecting the treatment fluid into a reservoir containing hydrocarbons.The fluids may be injected by using a bypass valve from water injectionsystem in the field to a holding tank while maintaining the temperatureabove about a freezing temperature, such as about 18° C. or higher.Injection pressure may be calculated to avoid fracture pressure atbottomhole conditions. The method may further include withdrawing,removing, extracting, and/or producing hydrocarbons from the reservoir.

According to some embodiments, a hydrocarbon recovery material mayinclude one or more organic acids (e.g., any acid described herein suchas cyclopentane carboxylic acid, L-proline, cyclohexane carboxylic acid,3-cyclohexane propionic acid, p-toluic acid, other naphthenic acids(e.g., those acids having the general formula C_(n)H_(2n-z)O₂ where n isthe number of carbons and z is the unsaturation), or compounds withmultiple carboxylic acid groups) in a water material (e.g., an injectionwater material). The concentration of organic acid may be about 100 mMor less, such as about 10 mM or less, such as from about 0.1 mM to about10 mM, such as from about 0.2 mM to about 2 mM, such as from about 0.5mM to about 1 mM.

In some embodiments, heating (such as at a temperature of greater thanabout 18° C., such as from about 18° C. to about 40° C.) can be appliedto dissolve the organic acid in the water material.

In some embodiments, the injection water material may have a salinityhigher than the low-salinity limit of about 5,000 ppm of salinity, butlower than about 100,000 ppm, such as from about 10,000 ppm to about50,000 ppm. In some embodiments, the injection water may have a salinityvalue below about 5,000 ppm. In some embodiments, the brine solution maybe specially developed for the particular reservoir, which is calledsmart water. Smart water may have sulfate and/or other ions at an amountthat is about 3-5 times higher concentration than seawater, and thetypical salinity of seawater is about 40,000 ppm. Injection brines canbe any composition of salts generally similar to the connate water butcan also be some developed smart water, which results from the additionof determining ions, generally specific to reservoir conditions. Thesalinity and ions present may impact which acid(s) may be used, and atwhich concentrations. Reservoirs can employ some aspects of smart waterflooding and addition of these acids could be considered an extension ofthis applied design.

In some embodiments, the injection water material may be seawater oftypical salinity of from about 30,000 ppm to about 40,000 ppm, or softwater, such as water from fresh aquifer sources having from about 500ppm to about 5000 ppm of salinity. In some embodiments, theconcentration of barium and/or strontium in the water can be about 1 ppmor less. Other water material may be sulfate- or calcium-enrichedseawater or briny material below about 100,000 ppm of salinity,depending on reservoir characteristics.

In some embodiments, the materials and methods described herein can beused in reservoirs (containing, e.g., hydrocarbons) having temperaturesof from about 10° C. to about 250° C., such as from about 15° C. toabout 150° C., such as from about 20° C. to about 120° C. Thistemperature enables the acids to remain soluble and decreases thelikelihood of forming viscous phases in the aqueous phase. In someembodiments, the materials and methods described herein can be used inreservoirs (containing, e.g., hydrocarbons) having pressures of fromabout 0 psi to about 15,000 psi, such as from about 300 psi to about10,000 psi.

Oil is comprised of four main solubility classes: saturates, aromatics,resins, and asphaltenes. Asphaltenes are polycyclic heteroatomcontaining compounds which are insoluble in pentane, hexane, and heptanebut are soluble in toluene. Asphaltenes are polar and are thereforeinterfacially active (and can alter interfacial properties) and maycause refining problems, such as emulsion formation and precipitation.Asphaltenes are believed to contribute to the formation and build-up ofthe interface between oil and water. Interfacial viscoelasticity isbelieved to relate to asphaltene content. As the interface between oiland water builds over time, oils with higher concentrations ofasphaltenes display increasingly higher viscous and elastic moduli. Onthe other hand, heavy oils are shown to take longer to form a stiffinterface. While not being bound by theory, it is believed that theinterface formation from heavy oils is caused, in part, becauseasphaltenes take longer to travel to the interface and form structuresin such a viscous medium.

Typically, high fractions of asphaltenes are associated with poor oilrecovery, as polar species can increase retention to the rock interface.Core-flooding experiments on oils containing no asphaltenes observe adrop in recovery, rather than an improvement in recovery, indicating therelative influence of asphaltenes in fluid-fluid interactions. In termsof stabilizing the interface, asphaltenes are believed to work inverselyto the acids present in oil. As such, asphaltenes work to strengthen theinterface and the acids work to weaken the interface. It is believedthat naphthenic acids (e.g., compounds of the formula C_(n)H_(2n-z)O₂,such as cyclohexane carboxylic acids or cyclopentane carboxylic acids),and other organic acids (such as L-proline; and aromatic acids, forexample p-toluic acid) can displace or interact with other components ofthe crude oil, or components of the oil/interface (such as asphaltenes),to make them less available to act at the interface.

In some embodiments, sodium naphthenates (e.g., sodium salts of theconjugate base of the naphthenic acids) and/or other organic acidshaving a counterion can be used. The sodium naphthenates and/or otherorganic acids having a counterion can compete with asphaltenes foradsorption and can hinder the development of a rigid interface. As bothorganic acids (e.g., naphthenic acids), and asphaltenes are polar andattracted to the oil-water interface, the interfacial rheology can bestrongly dictated by the organic acid concentration (e.g., thenaphthenic acid concentration), the asphaltene concentration, and theratio of organic acid (e.g., naphthenic acid) to asphaltene in oil. Thetwo species are theorized to be in competition for real estate at theinterface, with size, viscosity, polarity, and concentration beingvariables which influence the interfacial rheology.

As described herein, it is believed that naphthenic acids can be used toadjust the oil-water interfacial viscoelasticity and oil-waterinterfacial tensions, and can improve oil recovery in corefloods.Naphthenic acids (NAs) and other organic acids are believed tocontribute to softening of the interface, as an increase in emulsioncoalescence is observed in the presence of a naphthenic acid and/ororganic acid.

Experiments were performed to evaluate the chemical properties of theNAs and their behavior at the oil-water interface. Partitioningexperiments were performed to track NA concentration in the aqueousphase after contact with the oil, and the pH was characterized to betterunderstand the nature of the species partitioning from the oil phase.Rheological experiments were performed to assess the interfacialresponse of each NA structure (and each organic acid structure) comparedto the low-salinity brine. The rheological results include the elasticmodulus and viscous modulus of the bulk oil phase and the interface.Rheology is the study of flow and deformation and is usually classifiedby the deformation response to force, predominantly in liquids.Depending on the fluid, size and shape of the geometry, various modes ofdeformation may result. A fluid's response to different deformationtypes can provide a comprehensive perspective of how the interfacestructuralizes and functions, and ultimately, link fluid-fluidinteractions with improved oil recovery.

EXAMPLES

Materials

The following carboxylic acids were acquired from Sigma Aldrich (St.Louis, Mo.) and the acids utilized in the embodiments described belowwere selected from the following: Dicyclohexyl acetic acid, cyclohexanepentanoic acid, 4-pentylbenzoic acid, 1-methyl-1-cyclohexane carboxylicacid, 5,8 cholanic acid, 2-hexyldecanoic acid, 4-phenylbutyric acid,cyclohexane acetic acid, 3-cyclohexane acetic acid, 3-cyclohexanepropionic acid, 4-heptyl benzoic acid, p-toluic acid, decanoic acid,cyclopentane carboxylic acid, (±)-4-methyl octanoic acid, cyclohexanebutyric acid, biphenyl-4-carboxylic acid, cyclohexane carboxylic acid.L-proline and a naphthenic acid mixture containing various unspecifiedC12-C14 cyclic acids were acquired Sigma Aldrich, and are used herein tocompare the results collected with a mixture shown to improve oilrecovery. Sodium sulfate (Na₂SO₄) was also procured from Sigma Aldrich;brine containing sodium sulfate was selected as a comparative. In someembodiments, the brine (or the low-salinity brine) can be aqueous sodiumsulfate (1% Na₂SO₄).

The oils analyzed in the embodiments described below were obtained fromsandy reservoirs in the state of Wyoming. Toluene and methanol wereutilized as cleaning fluids where oil and oily organics were used.Whatman ashless filters, PFGSE filters, and SFCA filters were purchasedfrom Sigma Aldrich, Fisher Scientific (Hampton, N.H.), and Celltreat(Pepperell, Mass.), respectively.

Sample Preparation

The crude oil used for the experiments herein, unless otherwise noted,is labeled as GB oil. The GB oil was centrifuged for about four hoursand filtered with, e.g., a 90 mm Whatman ashless filter under nitrogengas pressure before use. The oil was stored in an amber jar to protectit from UV decomposition and shaken thoroughly before each use.

A 1% Na₂SO₄ brine, equivalent to 2.24 mM (low salinity) and an ionicstrength of 6.7 mM, was prepared and vacuumed for two hours before use.The brine was selected because it served as the baseline aqueous phasefor the coreflooding experiments. Brine aliquots were then mixed witheach of the 18 acid solutions at various concentrations and mixed intosolution for several days. One acid, NA18, was especially soluble athigher concentrations and measurements were also performed at 2.5 mM, 5mM, and 10 mM for NA18. Several acids exhibited poor solubility despitevarious mixing times, heat applied, or the concentration attempted. Noadjustments were made to the brine to bring the acids into solution; athigher brine pH, larger naphthenic acids (NAs) solubilize more readily,while smaller ones can often dissolve at neutral pH. At higher pH, thepotential for micelle and reverse micelle formation increases. However,embodiments described herein relate to acids that partition naturally,rather than those coaxed from the oil phase, so pH adjustments were notmade in order to examine the influence of the acids in the system.

Of the 18 individual acids assessed, six were found to be insoluble inthe brine, while the others were compared for structural similaritiesand peak quality. In summary, four carboxylic acids (includingnaphthenic acids) were analyzed according to water solubility andstructural diversity: cyclopentane carboxylic acid (NA14), cyclohexanecarboxylic acid (NA18), 3-cyclohexane propionic acid (NA10), andp-toluic acid (NA12). The structures include a cyclopentane, acyclohexane, a cyclohexane with a chain, and an aromatic ring.L-proline, while not a naphthenic acid, was also analyzed due to itssimilarity in structure to NA14.

Additionally, the naphthenic acid mixture (NAmix1) was analyzed. TheNAmix1 solution was mixed at 1 wt % in the 1% Na₂SO₄ brine. The NAmix1is partially soluble in water at 25° C. and the undissolved oily film isremoved and discarded prior to investigation.

Density and pH measurements were derived for each acid solution on a DMA4500 Anton Paar Density meter (Ashland, Va.) and VWR Symphony SB70P pHmeter (Radnor, Pa.). ¹H NMR experiments were performed at 25° C. using aBruker Avance III 600 instrument. Chemical shifts were referenced towater as the internal standard. For each example acid, the spectralwidth was measured at 12 ppm and 256 scans were captured. The pulsesequence used applied an excitation sculpting solvent suppression for 1D¹H NMR, which works with samples in 90% H₂O and 10% D₂O. The instrumentwas allowed to select its own gain, which is often concentrationdependent. A time domain of 32,000 points was selected. In general, toprocess acid concentrations, the area of a control peak is taken to be 1and the area from 0-3 ppm is taken for every sample. Subsequently thisarea is normalized over the gain.

FIG. 1 illustrates ¹H NMR data for various example acids. In FIG. 1,individual structures are provided in addition to the fingerprint forthe numerous species present in the NAmix1 at 25° C. In NAmix1, whichwas shown to increase oil recovery, no water-soluble aromatic compoundsare seen in the NMR data.

With reference to the NAmix1 in contact with the GB oil, the data showedthat no aromatic compounds partition into the aqueous phase, with orwithout acids in the initial aqueous phase as seen in FIG. 5 (discussedfurther below). Despite the lack of aromatics seen in the NMR data ofNAmix1, NA12 was selected to further characterize the interfacialeffects elicited by cyclohexanes and to explore aromatics asinterfacially active species.

Crude Oil Characterization

Table 1 shows characteristics of various crude oils—labeled as TC, WB,and GB. The asphaltene content (C₅ wt %) of these crude oils wasdetermined by stirring an aliquot of oil (1 g of oil) in 40 g ofanalytical grade n-pentane to form a 1:40 by weight solution of oil ton-pentane. Asphaltenes are the portion of oil insoluble in short-chainalkanes; as such they collect on the filter when filtered under vacuum.The solution was allowed to stir at about ambient conditions for about afull day. The solution was then vacuum filtered through a 0.45 μm PFGSEfilter paper and rinsed with pentane until the solution rinsed clear toprevent asphaltene deposition to the glass. The solution was maintainedunder vacuum until small cracks appeared on the asphaltene fractionremaining on the filter. The asphaltene precipitate and filtrate weredried in an oven until the weight stopped changing, indicating that nomore solvent was evaporating, and the asphaltene precipitate remainedsubstantially free of other constituents. The asphaltene fraction wasdetermined by the weight of the precipitate as compared to the originalaliquot of oil in the solution.

The crude oil viscosity was determined using a parallel plate geometryon an ARES rheometer from TA instruments (New Castle, Del.). The strainwas held steady for a frequency sweep on a range of 1-200 Hz with a gapof 0.3 mm. Ten measurements were made per decade to provide the resultsin Table 1. The acid content was determined through ¹H NMR on theaqueous phase extracted from various partitioning experiments. Densitywas determined through with an Anton-Paar density meter and wascollected a minimum of five times to collect an average. Refractiveindex was determined by using a refractometer and was collected aminimum of five times to collect an average.

TABLE 1 Acid Content Asphaltene Content Viscosity Density Refractive Oil(N Area) (C₅ wt %) (cP) (g/mL) Index TC 5.6817 5.5 64 0.91 1.515 WG1.2652 10.5 105 0.92 1.527 GB 1.3013 9.7 90 0.91 1.5205

The calculation for normalized area of NMR plots uses a quantifyingtechnique. The procedure allows determination of a relativeconcentration of a compound in solution compared to other standardscollected under the same conditions. Here, the fingerprint acid areas,normalized over the receiver gain, are compared to estimate thedifference in acid quantity yielded by each oil. The refractive index issimilar for all three oils (GB, WG, and TC) despite the difference inasphaltene content among them. The refractive index similarity indicatesthat the asphaltenes present in the TC oil are different and likely morepolar than the asphaltenes present in the WG and GB oils. The GB oil wasused for the following experiments.

Interfacial Characterization

Rheological experiments were conducted with the GB oil and alow-salinity brine (1% Na₂SO₄) spiked with low concentration of organicacids using a TA Instruments AR-G2 Rheometer with a double-wall ringgeometry. Measurement of the oil-water interface was performed using therheometer, as the ring of the rheometer was placed directly on thedenser phase, with the second phase added carefully at the end. Theshear viscoelasticities were recorded at 25° C. Measurements were run inoscillatory time-sweep mode to measure the shear viscoelastic moduli, asthe oscillatory time-sweep mode has high sensitivity to measure lowfrequency and torque values.

The stress response of the oil-water interface can be calculatedutilizing Equation 1:σ(t)=γ_(o)[G′(ω)sin(ωt)+G″(ω)cos(ωt)]where σ represents the shear stress, t represents the time, γ_(o) is theamplitude of the strain, G′(ω) is the elastic or real modulus, and G″(ω)is the viscous or imaginary modulus. The elastic modulus is theinstantaneous response to stress and the viscous modulus is the delayedresponse quantified by a phase angle. The tangent of this angle isrepresented by the following equation:

${\tan(\delta)} = \frac{G^{''}}{G^{\prime}}$

Experiments were run in the linear viscoelastic region, determined witha strain sweep test at fixed frequency on individual samples todetermine appropriate values for each parameter in the followingexperiments.

The rheometer was cleaned with toluene and methanol and then air-dried;the Pt/Ir ring of the rheometer was flamed to remove residualcontaminants and salts before each experiment. The rheometer waspositioned on an air-table and was calibrated for geometry, inertia, andfriction before each experiment was prepared. The brine was filteredthrough a 0.45 μm SFCA filter and examined for bubbles before the ringwas lowered to sit at the interface. Next, the oil was added on top ofthe brine in a manner selected to avoid disruption of the interfaceformed. Without moving the table, the setup was covered and allowed torun for a minimum of five days. The viscoelasticity was measured severaltimes during the first day and then routinely once a day for theremainder of the experiment duration. The temperature was controlledwith the Peltier plate beneath the sample holder. When cleaning therheometer at the end of the experiment, care was taken to recover asmuch aqueous phase as possible for NMR and pH measurements.

The interfacial viscoelasticity measurements were conducted on sampleshaving a ratio of two parts aqueous phase to one part oil phase. Anaqueous phase was collected with only the brine solution, and then theacids selected were all measured at a concentration of 1 mM in thatbrine. NA18 was especially water soluble and thus higher concentrationswere measured, including 2.5 mM, 5 mM, and 10 mM. Results show thatincreasing the concentration from 1 mM NA18 to 2.5 mM NA18 decreases theviscoelastic moduli, however this change plateaus and similar resultsare collected for 2.5 mM, 5 mM, and 10 mM, which may suggest that theacids are aggregating in the water phase and the increase inconcentration may not, in fact, increase the amount of acid acting atthe interface. These results are supported by the NMR results (i.e. theconcentration increases between 1 and 2.5 mM, but results agreeregarding aggregation above this concentration).

FIGS. 2A-2C show rheology data for NA18—the most soluble acid of thosetested, as described above—at various concentrations according to someembodiments. The data illustrates that although the G′ modulus and G″modulus decrease with time, the ratio (tan(δ)) increases with anincreasingly acidified brine. The tan(δ) value is related to the abilityof a material to damp and the degree of structure within the fluidinterface. The values for tan(δ) show that there is more structuring asthe concentration increases, which is believed to be evidence in supportof the acid aggregating with itself in the aqueous phase.

FIGS. 2A-2C show that the interfacial viscoelasticity can be nearlyhalved using a 1 mM acid concentration, and the interfacialviscoelasticity continues to decrease with increasing acidconcentration. At day 5, the G″ value (viscous modulus) for the 1%Na₂SO₄ in oil is about 65 mPa, the 1 mM NA18 acid in oil is about 35mPa, the G′ value (elastic modulus) for the 1% Na₂SO₄ in the oil isabout 225 mPa, and the 1 mM NA18 acid in the oil is about 100 mPa. Atday 5, the 10 mM NA18 acid in oil example reached an interface that was21.2% of the un-acidified brine values.

The data shows that higher acid concentrations can continue to decreasethe viscoelasticity of the interface even with a mid-weight oilcontaining about 9.7% asphaltenes. The data also shows that a dramaticchange in viscoelasticity is also observed at concentrations as low as 1mM. The 5 mM and the 10 mM values correlate very closely with both theinterfacial rheology and the NMR data (Table 2; NMR data not shown).Accordingly, once a surfactant has reached its critical micelleconcentration (CMC), the amount of individual molecules adhering to theinterface does not increase, and the interfacial measurements plateauwhich is indicative of acid aggregation. However aggregates can stillform structures with the interface.

Considering the experimental data collectively, the NMR andviscoelasticity data suggest the formation of aggregates in the solutionat higher concentrations. The NMR signal can be analyzed such that adifferent trend can arise in the presence of aggregates than singlemolecules. Additionally, aggregates can interact with the interfacedifferently than single molecules, as demonstrated with minimal changein viscoelasticity values at higher concentration. As the other acidsincluded in this study are considered to be less soluble than NA18, anacid concentration of 1 mM is used to compare the remainder of thesolutions.

FIGS. 3A-3C show rheometric data for the example acids at aconcentration of 1 mM. The data shows that the cyclohexanes all decreasethe viscoelasticity of the interface. Acids NA18 and NA12, the twosmallest 6-membered rings examined, exhibit very similar viscoelasticitytrends. NA10, which is also a cyclohexane but with a longer carbon chainbetween the carboxylic acid and the cyclohexane, has viscoelasticityvalues that lie between the NA18 and NA12 and the un-acidified brine. Itis believed that the smaller molecules interact more strongly with theinterface while the larger NA10 provides intermediate viscoelasticresults, which is indicative of emulsion destabilization, thussupporting the theory that there is more to fluid-fluid interactionsthan just viscoelasticity.

A surprising difference is noticed when NA14 is tested, as thecyclopentane dramatically increases the individual viscous modulus andelastic modulus. The interface reaches such high elasticity values thatit seems to break, but then continues to increase in elasticity as if itwere repaired. A broken interface can show viscoelasticity values whichcontinue to decrease with time. This unexpected behavior provoked theinvestigation into the amino acid L-proline, which has a similarstructure to NA14 but this amino acid replaces a ring carbon atom withnitrogen atom.

FIGS. 4A and 4B show the interfacial rheology data for L-proline.L-proline exhibits initially low values of both the G′ modulus and theG″ modulus, but after day 2, the values spike and continue at anincreased rate for another week before plateauing. The results in thisexperiment, and in the NA14 case, indicate that cyclopentane structuresmay work to mend the interface if that interface is disrupted.

The plots of tan(δ) for the example organic acids are given in FIGS. 3Cand 4B. The NAmix1 softens the interface that results in a weakerinterface. Although having a different chemical structure, the NA12 aciddisplays very similar values for the interfacial dampening, but the NA12acid is aromatic and typically not observed in the aqueous phase, whichdoes not imply that it is not present in the oil phase. The aromaticspecies also showed tighter interfacial packing than saturated systems.While not being bound by theory, it is believed that the aromaticstructure of NA12 fits closely with the asphaltenes collecting at theinterface from the oil side. The NA10 acid and the NA18 acid showsimilar interfacial softening behavior, as do the NA14 acid and the 1%Na₂SO₄ brines.

In this instance, acids that decrease the viscoelastic moduli are shownto increase interfacial dampening/softening/tan(δ), while the tan(δ) ofNA14 is well-overlapped with the unadjusted brine values, despite theaforementioned increase in individual moduli. This indicates that NA14can be used to adjust the interfacial response. Table 2 illustrates theeffects of each acid on the interfacial viscoelastic moduli compared tothe brine viscoelastic moduli. It is believed that the adsorption ofnaphthenic acids generally softens or destabilizes the interface, whichcan be seen in the tan(δ) values. These effects typically promotecoalescence, which can be assessed with the emulsion stability datadescribed herein.

TABLE 2 Acid Solution Fractional G′ Fractional G″ tan(δ) 1 mM NA10 60%78.9% 131% 1 mM NA12 25.8%   48.8% 189% 1 mM NA14 151%  137% 90.6%  1 mMNA18 42% 53.5% 127% 1 mM L-Proline 53%   47% 114% 1 wt % NAmix1 12%  23% 188%

¹H NMR was also used to track changes in concentration of NA fractionsfrom partitioning experiments. Partitioning experiments were performedto acquire NMR data for the aqueous phases of various acids in contactwith the GB oil. Samples of the various organic acids (in brine) incontact with the GB oil were made having an oil-brine volumetric ratioof about 45:1. Each brine was placed in a glass jar and GB oil was thencarefully placed on top of the brine. The jars were sealed with ascrew-lid and placed in ovens at about 25° C. and left for a total ofabout 5 days. The samples were collected from each jar and pHmeasurements were taken after 0.5, 1, 3, and 5 days. Care was taken tominimize temperature changes and mixing of the phases. The pH probe wascarefully calibrated at about 25° C. before each set of measurementswere collected. After the predefined period of time was completed, asample of 630 μL was taken and placed in a 9″ NMR sample tube with 70 μLD₂O. A 600 MHz Bruker Avance III instrument was used to collect NMRspectra at 25° C., using a spectral width of 12 ppm and 256 scans and anexcitation sculpting solvent suppression. The control of the spectralgain was given to the instrument for the entire experimental matrix asthis is largely concentration dependent. The spectra were analyzed tocompare organic acid concentration in the brine phase over time atdifferent temperatures.

The partitioning experiments were conducted on the GB oil with theNAmix1 in the low-salinity Na₂SO₄ brine (2 parts aqueous phase to 1 partoil, volume ratio) over the course of 5 days to observe the motion ofthe myriad acids starting out in the aqueous phase. FIG. 5 illustratesthe difference between the initial acid species and the final acidspecies for NAmix1 and 1% Na₂SO₄ in the oil. More specifically, FIG. 5shows ¹H NMR data for the NAmix1 before contact with the GB oil, NAmix1after a 5-day contact time with the GB oil, and 1% Na₂SO₄ after a 5-daycontact time with the GB oil. The 1 wt % mixture (e.g., NAmix1) has aninitial acid content that is not only more diverse, but also at a higherinitial concentration than the other acids examined (1-10 mM).

The bottom spectrum of FIG. 5 shows the acids of NAmix1 which partitionfrom the GB oil into the 1% Na₂SO₄ after 5 days of contact. The NAmix1data shows that the initial NAmix1 spectrum is complex, as there areseveral species present with 12-14 carbons each. The difference inspectra between the initial NAmix1 before contact with the GB oil andthe NAmix1 after a 5-day contact with GB oil is clearly observed by theloss of several peaks, some of which are circled in FIG. 5. This loss ofsome signals indicates that some species are either forming new bonds orleaving the aqueous phase. Acids initially present in the aqueous phasecan leave the aqueous phase to either partition to the oil phase or sitat and work to build up the interfacial film between oil and water. Theformation of new species is not ruled out; however, there are few newpeaks observed which would support that outcome.

Emulsion Stability Analysis

Dispersions were prepared in a 1:1 volume ratio with GB oil to each acid(1 mM) in the 1% Na₂SO₄ brine. The dispersions were emulsified viacentrifugation at 6500 rpm for 30 seconds in an Ultra Turrax T25 basic(IKA-Werke) homogenizer. The emulsions were then homogenized for 3minutes at 6500 rpm to obtain homogeneous droplets for characterization.

Water-in-oil emulsions were prepared for each acid and the timeevolution was tracked on a Bruker Biospin Minispec mq20 time domainnuclear magnetic resonance (TD-NMR). This instrument providesinformation about the polydispersity (σ) of the system and the diametersize (d_(i)). The variable i can represent either the diameter in termsof the number of droplets (i=0) or the diameter in terms of averagevolume of the droplets (i=3). The unimodal droplet size distribution forthe created emulsions can be calculated according to Equation 2:

${q_{i}(d)} = {\frac{1}{d\;\sigma\sqrt{2\pi}}e^{- \frac{{({{\ln{(d)}} - {\ln{(d_{50,i})}}})}^{2}}{2\sigma^{2}}}}$where q_(i) is the log-normal distribution, d_(50,i) is the geometricmean diameter. Bruker software is used for the NMR and that calculatedthe droplet size distribution. The change in diameter in relation to thevolume is useful because it is indicative of coalescence. Thepolydispersity is also useful in terms of stability, as a system whichshows a change over time may be considered not stable.

This technique is advantageous as it is non-invasive and independent ofthe opacity of the dispersion. A unimodal log-normal function was usedas it has been shown to be a suitable density function to measuredroplet-size distribution on water-in-oil (W/O) or oil-in-water (O/W)emulsions. Droplet coalescence and emulsion stability was inferred bytracking the droplet-size distribution density over time.

Breakup and snap-off are shown to be the competing processes regarding aconnected oil phase in which the dominant process is dictated by oilsaturation. The influence of the specific acids on coalescence wasevaluated with restricted diffusion in a time-domain nuclear magneticresonance (TD-NMR) system. Water-in-oil emulsions were prepared for 1%Na₂SO₄, 1 wt % NAmix1, and each acid at 1 mM concentration. Measurementswere recorded within the first hour after emulsification, and every dayfor days 1-5, and then on days 7, 10, and 14. The TD-NMR systemcalculates a median diameter, which relates to the number of dropletspresent (d₀) and the volume of the droplets present (d₃). The d₀ can beconsistently lower than the d₃, since small droplets, though higher innumber, contribute less to the overall volume of emulsion droplets.Conversely, droplets with larger diameters contribute to the greaterpart of the volume, but do not exist in large quantities. The Brukersystem software also provides a standard deviation, σ, which isapplicable for both diameter values and relates to the polydispersity ofthe droplets in solution. A combination of this a value with eitherdiameter value in Equation 2 allows for a calculation of the densitydistribution functions for the acids, as seen in FIGS. 6A and 6B.

FIGS. 6A and 6B show the density distribution functions of example acidsat 1 mM concentration on day 1 and day 14 according to an embodiment.The NAmix1 elicits the most monodisperse emulsions on day 1, compared to1% Na₂SO₄ and the other acids. NA12, NA14, and NA18 also show greatermonodispersity on day 1 than does the brine alone. However, NA10 andL-proline are more polydisperse. This indicates that the shearing formsemulsions differently based on the organic acid present. On day 14 theorder changes, and L-proline is the most monodisperse emulsion solution,followed closely by NA14 and NA18. L-proline, NA14, and NA18 arebelieved to qualitatively stabilize emulsions compared to thelow-salinity brine (1% Na₂SO₄). NA10, NA12, and NAmix1 all increase thepolydispersity more so than does 1% Na₂SO₄, which is believed toindicate a destabilization of the emulsion system. The stability ofemulsions decreases over time, evidenced by the increase inpolydispersity and diameters of all emulsion systems.

Analyzing the changes on a per acid basis elucidates the individualbehavior. FIGS. 7A-7G illustrate an overlay of each acid on day 1compared to day 5 and day 14. The clear shift to increasing diameter andincrease in polydispersity which occurs over time is visible. NAmix1(FIG. 7B) and NA10 (FIG. 7C) stand apart when compared to acids which donot cause such a dramatic shift, such as L-proline (FIG. 7G). L-prolinehas the lowest curve on day 1 and changes the least; L-proline reachesequilibrium faster than the others, as indicated by the similarity inthe curves for day 5 and 14. While NA10 also has a low curve on day 1,NA10 shows a more dramatic widening, correlating with a greater increasein polydispersity.

Table 3 shows the differences in these values for two time fragments: Δxfor days 1-5 and Δx for days 1-14, where x represents either d₃ or σ.The d₀, or number median diameter, is omitted as it relates very closelyto the σ value, as increasing polydispersity likely increases the numberof small droplets. The comparisons show that the rate at which acidsstabilize or destabilize the emulsions is time-dependent. Allstabilization or destabilization comparisons in Table 3 are made with 1%Na₂SO₄ as the control.

TABLE 3 Time Influence on Emulsion Destabilization by Acids AcidSolution Δd₃ day 5 Δσ day 5 Δd₃ day 14 Δσ day 14 1% Na₂SO₄ 1.4705 0.1621.641 0.273 1 wt % NAmix1 1.352 0.286 1.705 0.375 1 mM NA10 1.46 0.23451.65 0.3755 1 mM NA12 1.315 0.19975 1.6025 0.34625 1 mM NA14 1.34751.3475 1.4425 0.259 1 mM L-Proline 1.045 0.1325 1.115 0.17225 1 mM NA181.5395 0.12625 1.572 0.22375

The change in volume (Δd₃), based on the acid, from day 1 to day 5 andfrom day 1 to day 14 has the following ranking:

day 5: NA18>Na₂SO₄>NA10>NAmix1>NA14>NA12>L-proline

day 14: NAmix1>NA10>Na₂SO₄>NA12>NA18>NA14>L-proline

This change in ranking from day 5 to day 14 shows that the acids notonly act differently based on structure, but the effect istime-dependent. NAmix1 destabilizes emulsions the most, while L-prolineallows the most stabilization of emulsions. In this sense, the long-termstability behavior resolves as shown above.

FIG. 7 illustrates a density distribution function as a function ofdroplet diameter for the various acids. Polydispersity is utilized toinduce capillary motion, as there will be substantially no change inpressure in a monodisperse system, which would remain capillary trapped,provided the oil ganglia are larger than the adjacent pore throats, butsmall enough to not overcome capillary barriers through viscous drag. Onday 14 it was observed that L-proline, NA14, and NA18 act to stabilizethe emulsions compared to the behavior shown by the 1% Na₂SO₄ emulsionsolution: these acids show minimal change in diameter and polydispersitycompared to the brine emulsions.

NA10 and NAmix1 show a larger increase in the d₃ compared to the brineand a greater increase in polydispersity, indicating that these acidsdecrease the stability of the emulsions. NA10 consistently demonstratesthe highest σ values, indicative of highly polydisperse emulsions, asshown by the shorter and wider dispersion graphs than the other emulsionsolutions in FIGS. 7A-7G. On day 14, NA12 has a greater polydispersitythan the brine alone, but does not show an increase in diameter to thesame extent, indicating that NA12 does not encourage coalescence, butdoes not particularly stabilize the emulsions present. These resultsindicate the generalization “naphthenic acids stabilize emulsions” canbe more accurate for a time period of less than a week, but by two weeksa napthenic acid's ability to stabilize emulsions can bespecies-dependent.

Neck Diameter

Cyclopentane carboxylic acid (NA14), cyclohexane carboxylic acid (NA18),3-cyclohexane propionic acid (NA10), and the low-salinity brine (1%Na₂SO₄) were used to make example acidified brine in oil systems for theneck diameter experiments. The systems used for the neck diameterexperiments include about a 1:10 ratio of the GB oil phase to aqueousphase (1 mM of NA10 in 1% Na₂SO₄, 1 mM of NA14 in 1% Na₂SO₄, 1 mM ofNA18 in 1% Na₂SO₄, and 1% Na₂SO₄). The oil is ejected from one needletip and then attached to another needle and stretched between the two.The brine is gently added and the system is aged before oil is withdrawnfrom the suspended bridge. The more oil that is removed before thebridge snaps can be indicative of a system that delays snap-off andallows more oil to stay mobilized in porous media.

A bridge technique was executed on a modified First Ten Angstroms (FTA)1000 pendant drop instrument using two opposing vertical needles. Theslenderness ratio (A) is defined as the length of the bridge (L) dividedby the diameter of the needle (D). A large slenderness ratio isassociated with an unstable bridge. The bridge goes through at least twoprocesses. First the oil is bridged between the opposing needles,suspended in the brine and aged up to one hour. While the bridge isaging, the interfacial elasticity increases and the interfacial tensiondecreases. There are no disruptions or deformation of the system, andthus the surface stress is equal to the interfacial tension. Afteraging, the bridge goes under the second process during which the oilcomprising the bridge is removed at 0.1 μL/s. This response is trackeduntil bridge failure. During this process, due to the increase in theelasticity of the interface, an extensional longitudinal and compressivecircumferential surface stress contribute to the process. The behaviorof the oil when the bridge breaks is indicative of the dominantenvironment of the oil-water interface—e.g., whether the environment ischaracteristic of an elastic break or an inelastic break. An enhancedelastic break, resulting from the formation of a thick interface, canappear as pointy interface and can show very little recovery of itsinitial shape, while a viscous break can reform the initial appearanceof the oil before the formation of the bridge as shown in FIGS. 8A-8C.FIG. 8A is an image of the bridge initially before any aging or oilremoval. FIG. 8B is an image showing the behavior observed in aninelastic break, and FIG. 8C is an image showing the behavior observedin an elastic break. Increased viscoelasticity suppresses interfacialsnap-off and helps to sustain a more continuous oil phase. An elasticbridge is much less prone to break and therefore can pull more volumesof oil out (more production).

The behavior of the bridge is monitored with an APPRO camera at a framerate of 60 frames per second and its geometry is tracked by measuringthe neck diameter (ND). The neck diameter is the lowest radius along thevertical axis. The critical neck diameter (CND) is the valuecorresponding to the last frame of the connected bridge. The ratio ofCND/ND is a stability proxy, and assumptions are made that a value closeto zero indicates prevalent elastic forces. All of the unaged systemspresent an axisymmetric surface stress, while the aged system's stressresponse varies with the aqueous phase. After the bridge is broken thedrops of oil on each needle tip retain the pointy shape in an elasticexperiment rather than resuming a drop-like appearance as in aninelastic scenario. This indicates that a more elastic interface cansuppress the snap-off effect.

The response of the oil was analyzed for three organic acids (NA14,NA18, and NA10) and the brine (1% Na₂SO₄).

The measurements are tracked immediately after one hour of aging timeand show different behaviors for each system. FIG. 9 shows images fromwhich the CND for each example system was measured for the unagedexample systems determined directly before bridge failure. The bridgeformed for NA10 appeared to be inelastic, similar to that shown forNa₂SO₄. Based on the viscoelasticity data collected on the AR-G2rheometer, these results correlate with snap-off times similar to thebrine alone. This suggests that NA10 may not maintain connectivity inthe reservoir, however emulsion stability data suggests that it wouldencourage coalescence, and therefore it could work to re-establish thisconnected phase once it has been lost.

The CND was measured for various times between the start and one hour.Some experiments can take a day or more before differences betweensystems can be observed, but the acids impact the interface rapidly anddramatically. The impact of the acids can be seen by comparing any ofthe acidic systems to the brine alone (FIG. 9). FIG. 10 shows thedifference in bridge behavior and the change in CND for the examplesystems as each system is aged according to some embodiment. The neckdiameter for the smaller acids (NA14 and NA18) and brine in oil at theinitial time are very similar as shown in FIG. 10. After 1 hour, theresults show statistically different behavior and the systems containingNA14 and NA18 are approaching stability (CND=0). At 1 hour, thestabilization time for the system containing NA18 is short (CND valueclose to 0), and the stabilization time for the system containing NA14is significantly lower than the value for the system containing only thelow-salinity brine (1% Na₂SO₄).

FIG. 11A shows the neck diameter (ND) to IND for NA14, NA18, and brinein oil as the systems age according to some embodiments. FIGS. 11B-11Dshow images of the final frame of connection before the bridge fails forthe example systems, which is at or close to the 1 hour CND bridgeresponse. FIG. 11B is an image of the 1% Na2SO4 brine in oil system,FIG. 11C is an image of the NA14 in oil system, and FIG. 11C is an imageof the NA18 in oil system.

After aging for 1 hour the bridge systems displayed different behaviorscompared to the un-aged system as seen in FIGS. 11A and 11B. For thesystem containing the low-salinity brine alone, the CND is much narrowerafter one hour of aging time (FIGS. 11A-11D) than initially and there ismore change in shape before the system undergoes snap-off. When thelow-salinity brine system does snap-off, the system exhibits inelasticbehavior, while the systems containing the acid show more acute elasticbehavior. The system containing NA14—the cyclopentane carboxylic acidthat showed an increase in viscoelasticity value and the tan(δ) valuestarting above 1—shows a distinct difference from the low-salinity brinealone. The shape is still symmetric, but the behavior is very differentand has a CND value closer to 0.

As shown in the CND plot for the aged data (FIG. 11A), snap-off isdelayed in the case of both the NA14 system and the NA18 system. TheNA18 and NA14 system delays snap-off compared to the low-salinity brinesystem. The NA14 system also shows a more elastic break (FIG. 11C) thanthe other systems tested. FIG. 11D shows the unusual nature of NA18, inthat it sort of appears elastic but different from the elastic resultsin FIG. 8 (and every other elastic result collected on this instrumentto date); NA18 appears to be creating its own asymmetric elastic skin.It should be noted that although NA18 showed a decrease inviscoelasticity, the “skin” enables it to delay snap-off through its ownmechanism.

The NA18 system (cyclopentane carboxylic acid) showed a drop inelasticity, but this system delays snap-off even longer than the NA14system. While not being bound by theory, this is likely related to theobserved solid-like film (or skin) on the exterior of the bridge that isshown in FIG. 12. The bridge for the NA18 in oil system shows evidenceof an interfacial film, strengthening the bridge, and further delayingsnap-off, allowing even more oil to be removed before failure.

FIG. 12 shows an image during bridge deflation (e.g., when oil is beingremoved from the bridge) for the NA18 in oil system after 1 hour ofaging, according to some embodiments. 1.583 s is the time lapse betweenthe image on the left (closed line) and the image on the right (arrow).The skin shows wrinkles and a thin-film as the bridge collapses. Thisregion is likely in the non-linear viscoelastic regime and such behavioris unexpected as the other measurements are in the linear viscoelasticregime. If applying external force causes this acid to behavenonlinearly it can be more difficult to predict its behavior. The bulkoil is extracted by the pump leaving the interface comprised of the mostpolar species in the oil such as asphaltenes and naphthenic acids. Thisinterface allows the bridge to last longer than other systems (FIGS.11A-11D), as a stronger interface for NA18 is clearly shown. Even thoughthe skin is usually expected to form when the aging time is greater thanthe stabilization time (CND=0), the solid-like film was visible in theNA18 system after about 10 minutes, making it difficult to determine thestabilization time and therefore producing a drastic and fast drop inthe CND as can be seen in FIG. 10. This observation shows that acids arefast-acting and interfacially active.

For the brine system and the NA14 system, the skin was observed afteraging the bridges for approximately 24 hours and 12 hours, respectively.In addition, for the brine system and the NA14 system, the aging timeswere greater than the stabilization times.

The data showed a spike in elasticity for the cyclopentane acid (NA14)while the cyclohexane acids have a detrimental effect on theviscoelasticity. The viscoelasticity data suggests that the cyclohexaneacids (NA18 and NA10) may elicit similar responses from the oil, as theyboth drop the moduli to varying degrees. This difference in behaviorbetween NA18 and NA14 is significant because these two acids show thatit is the difference between increasing or decreasing the elasticity.The reparative quality indicates that the acids can encouragecoalescence.

The inelastic state of NA10, predicted by the NMR, is represented wellby its inelastic bridge. This acid does little to delay snap-off.

Effect of Temperature on Interfacial Viscoelasticity

The effect of temperature on interfacial viscoelastic properties can beevaluated considering only the control brines at various temperatures.As shown below, the interfacial viscoelastic properties clearly increasewith increasing temperature. This effect of temperature shows theimportance of rheological analysis at high temperature.

A Wyoming crude oil (WG) from a sandy reservoir was used to examine thetemperature effects on viscoelasticity. The oil was centrifuged for fivehours at 7500 rpm, and filtered with an 11 μm particle retention filterpaper to remove traces of water and contaminants. Properties of the WGcrude oil at 25° C. include a density of 0.921 g/cc, viscosity of 136.56cP, pentane-asphaltene content of 9.3 wt %, and refractive index of1.527. Properties of the WG crude oil at 80° C. include a density of0.8984 g/cc, a viscosity of 20.7 cP, pentane-asphaltene content of 9.3wt. % and refractive index of 1.504.

Synthetic brine solutions were prepared by adding analytical grade salts(NaCl, Na₂SO₄, NaHCO₃, MgCl₂.6H₂O, and CaCl₂.2H₂O) to deionized (DI)water. Table 4 shows general properties of each brine at 25° C. Theseawater (SW) brine modeled from a reservoir in the Gulf of Mexico wasused as the reference brine. The synthetic brine OS is seawater devoidof sulfate ions, where the 3S and the 5S brines contain three and fivetimes the sulfate content of the SW brine, respectively. The 10% SWbrine corresponds to the SW brine diluted down to 10% by the addition ofDI water. The ionic strength is the same for all brines except for the10% SW brine. All brine and oil samples were placed under vacuum beforeany interfacial rheology measurements. All of the brines were maintainedat atmospheric equilibrium. Mineral precipitation was not observed underexperimental conditions.

TABLE 4 Density SO₄ ²⁻ Ionic Strength Brines TDS (ppm) (g/mL) pH (ppm)(M) SW 35,190 1.02259 6.96 2,900 0.65 0S 36,600 1.02121 6.68 — 0.65 3S33,200 1.02553 7.00 8,700 0.65 5S 39,670 1.02722 7.50 14,500 0.65 10% SW5,460 0.99969 6.82 290 0.035 TDS is total dissolved solids.

A spinning drop video tensiometer (SVT20) from DataPhysics was used toevaluate the extensional rheology of the oil:brine interface. A dropletof the WG oil is injected into the higher density brine within thecapillary tube. The samples for the experiment were a 45:1 mixture ofbrine in oil. The capillary tube is rotated until a high angularvelocity results in an elongated drop shape. The droplet elongates untila balance between tension and centrifugal force exists at the interface.Interfacial tension (IFT) is calculated through optical techniques untila point in time where the IFT has stabilized. The droplet is thensubjected to viscoelastic tests where a stress is applied through anoscillating angular velocity. The amplitude of the rotational speed iscalculated through prerequisite amplitude tests to ensure thedeformation remains within the linear viscoelastic region characteristicof the interface. The amplitude used, given in percent of the steadyrevolutions per minute (rpm), was 7% at 25° C. and 5% at 80° C. Afrequency sweep was also performed, using a frequency of 0.05 Hz. Afterabout 15 oscillation cycles, the IFT evaluated from each video frame isused to calculate the viscoelastic moduli. Oscillation tests areperformed every hour for at least 11 hours to evaluate how interfacialviscoelasticity (IFVE) changes with time.

IFVE moduli were measured through extensional rheology using thespinning drop oscillation method. Elastic and viscous moduli aredisplayed for the WG crude oil in various brines (the SW brine, the OSbrine, the 3S brine, the 5S brine, and in the 10% SW brine) at 25° C.and at 80° C. in FIGS. 13A-13D. The interfacial systems at lowtemperature exhibit more of a viscous behavior for the duration of theexperiments. The last points of the low temperature curves suggest thatthe oil-10% SW brine system, the oil-3S brine system, and the oil-5Sbrine system have the highest elastic modulus, while the oil-10% SWbrine system has the highest viscous modulus.

A shape factor is calculated by a Young-Laplace drop-profile fittingprocedure; therefore, a symmetric drop is used for accurate IFTcalculation. Although asymmetry was not detected in the oil-SW brinesystem, the elastic modulus begins to increase at a high rate after 10hours and the viscous modulus follows a similar trend compared to theoil-10% SW brine system. Of the other brines, the oil-SW brine systemyields the highest viscoelasticity. The oil-3S brine system has thelowest viscoelastic moduli. Imbibition results, discussed below, showthat the highest oil recovery comes from the interaction of the WG oiland the 3S brine at high temperature. It is possible that a wettabilityalteration has a greater influence as a mechanism of improved oilrecovery being that contact angle results at high temperature show ashift to more water-wetness. Nevertheless, the 3S brine system alsoexhibited less stable emulsions at 80° C. suggesting increasedcoalescence and mobilization of fluids.

Each spinning drop experiment is left to rotate for about two hours.This amount of time is sufficient for low temperature experiments, butthe IFT continues to change slightly under high temperature conditions.Low temperature results show the change in IFT over the course of eachexperiment is as follows: a decrease of 4.4% for the oil-SW brinesystem, an increase of 0.45% for the oil-10% SW brine system, a decreaseof 2.7% for the oil-OS brine system, and a decrease of 7.4% for theoil-3S brine system. At high temperature, the oil-3S brine system andthe oil-OS brine system exhibit a decrease of 7 and 3.5%, respectivelyin IFT values over 12 hours, while the oil-SW brine system and theoil-10% SW brine system realized a nearly 11% decrease. The oil-SW brinesystem and the oil-10% SW brine system utilize increased timescales forIFT stabilization, but this is believed to be caused by an asymmetricaldrop shape that results in a large error in IFT calculation.

Curves from FIGS. 13A-13D were normalized by the average interfacialtension (IFT) given after every oscillation test and shown in FIGS.14A-14D. Although the elastic and viscous moduli curves for lowtemperature are slightly less overlapping, the oil-10% SW brine systemexhibits the lowest E′/IFT trend because of its high IFT. Plots of thenormalized elastic and viscous moduli at high temperature show no changein trends from those shown in FIGS. 13A-13D.

The viscoelastic moduli are compared through the use of the phase angleshown in FIGS. 14E and 14F. The viscous modulus clearly dominatesinterfacial viscoelasticity at low temperature for the oil:brinesystems. High temperature results show the 3S brine initiates a moreelastic response at short contact times and this elastic-viscousrelationship shows little change throughout the experiment. Only theoil-10% SW brine and the oil-3 S brines realized a dominant elasticmodulus at high temperature.

The effect of temperature on IFVE properties can be evaluatedconsidering only the control brine at various temperatures. FIGS. 16Aand 16B show the elastic and viscous response to extensional deformationof the control brine and GB oil at 25° C., 40° C., and 80° C. The 40° C.curves are short, but progress between the low and high temperaturecurves. The steep ascent of the 40° C. elasticity curve is believed tobe the result of various interfacial processes initiated by elevatedtemperature. Interfacial viscoelastic properties clearly increase withincreasing temperature.

FIGS. 16C and 16D show the elastic and viscous response to extensionaldeformation of the 1 mM NA10 in 1% Na₂SO₄ and GB oil at 25° C., 40° C.,and 80° C. The curves for each temperature in these figures are clearlydistinct with no overlap and similar slopes. The effect of temperatureon the interfacial viscoelasticity can also be seen in FIGS. 16E and 16Fshowing the 1 mM concentration of NA18 in the control brine (1% Na₂SO₄)with GB crude oil at 25° C., 40° C., and 80° C. The 25° C. curves showlittle change compared to the other aqueous phases tested; however, the40° C. and 80° C. curves begin to overlap after about 10 hours. The twohigh temperature curves are still distinct in shape especially whenconsidering the elastic modulus. The change in slope of the curves withtemperature may be due to the adsorption kinetics of theinterfacially-active molecules. The rate at which asphaltenes adsorb tothe interface is likely different from the rate of naphthenic acidadsorption; this effect would certainly affect the shape of the curves.It is also possible that the arrangement of molecules at the interfacecould be less sterically hindered at lower temperatures. The differencein slope of the elastic moduli at 40° C. in FIGS. 16A and 16E could bedue to the rearrangement of molecules to optimally preserve theinterfacial structure. Nonetheless, the viscoelastic effects discussedherein also occur at high temperatures.

Imbibition

A vacuum saturation cell at about −40 kPa was first used to vacuum therock cores for about 12 hours to remove air trapped in the rock cores.The vacuum valve was closed once all air was removed. The oil valve wasslowly opened to allow GB crude oil to flow into the cell. The oil wasdrawn into the cores under reduced pressure. The saturated cores wereimmersed in a Hastelloy C-276 saturation cell filled with GB oil atabout 80° C. for about 14 days. Oil saturation was calculated from massbalance. Saturated cores were carefully placed in Amott cells and thenimmersed in the experimental brine solutions. Oil in the cores wasdisplaced by the brine solutions through gravity, buoyancy forces,and/or the reduction of capillary forces. Oil recovery volumes wererecorded until no more oil was recovered.

FIGS. 15A and 15B show imbibition data for exemplary acids in water-wetrock and oil-wet rock according to some embodiments. In water-wet rock,NA18 and NAmix1 can positively impact the recovery factor (RF). NA14 mayalso positively impact RF, as it did delay snap-off in the bridgeexperiments. NA10 showed low elasticity values and showed an inelasticbridge, suggesting that it may not maintain a connected mobile phase,even if it encourages coalescence.

With respect to the oil-wet rock, there is a significant spike fromNA14, where it actually recovers more oil than in the water-wetscenario. Additionally, oil is observed from the NA14 example before anyof the other systems, suggesting that NA14 changes the wettability toits advantage. This suggests that NA14 may be the most useful in oil-wetreservoirs early on in the process. NA18 and NAmix1 show similarly steepslopes, however at a later time in the game. Applying NA14 early on inthe process and then switching to NA18 may be a viable recipe, in someembodiments, for improved recovery factor in situ.

Embodiments described herein indicate that injection of organic acids(e.g., naphthenic acids and similar structures) enhance oil recovery.The structural specifics of each organic acid can be a factor ininterfacial behavior. Dramatic differences can be observed with suchsmall differences in the organic acids (e.g., naphthenic acids and otheracids), such as by one or two CH₂ groups.

The small cyclohexanes, such as NA10 and NA18, can work to decrease theviscoelastic moduli (G′ and G″), though NA18 does so more strongly. NA18is the most water soluble acid which surprisingly exhibits a dramaticdecrease in observed viscoelasticity. This is surprising because NA18 ishighly water soluble which is not typically indicative of oleophillicbehavior, and it was unexpected that NA18 would cause such significantchanges in the interfacial behavior. The degree to which the G′ and G″moduli decrease is concentration dependent, but G′ and G″ plateau at aconcentration at which the acid is believed to form aggregates, such asabove 2.5 mM for NA18. While not being bound by theory, it is believedthat the diminution may be related to how the acids sterically interactwith the interface. The steric interaction between NA18 and themolecules comprising the interface (e.g., asphaltenes) could lay flat orperpendicularly, or intercalate to a certain degree. The stericorientation is likely related to both the interfacial effects and thestructure of the acid.

NA18 and NA10 are likely to interact with the interface similarly,though it is believed that NA10 does so to a lesser degree, according tothe decreased interfacial effects. NA10 does not decrease the individualmoduli to the same extent as NA18, but NA10 softens to the same degreeas NA18 when the tan(δ) is analyzed. On day 5, the largest change in d₃,or most coalesced system, is NA18, though this may indicate a stablediameter for the system as it does not continue to appreciably increasebetween day 5 and 14. NA10 has the opposite time dependence, where it isthe least stable mono-acid system at the end of the 14 days, but is morestable than the brine on day 5. Thus, time may be a parameter for anyemulsion behavior.

NA12 (an aromatic NA) was analyzed to observe behavior of aromatic acidsat the water-oil interface and their effects on emulsion stability.While not being bound by theory, it is believed that with anoil-in-water emulsion, the aromatic species may be wedged into theinterface as deeply as possible in an attempt to get to the water phase.This indicates the acids that decrease the viscoelasticity the most,e.g., NA18 and NA12, are both the most water soluble. Thesewater-soluble species are not believed to stabilize emulsions comparedto the brine alone. NA12 does not stop droplet breakup, based on theincrease in polydispersity, and the droplets do not show evidence ofcoalescence through an increase in diameter. This is surprising asNAmix1 exhibits similar interfacial damping behavior to NA12, butdissimilar coalescence behavior to NA12. The asphaltenes are alsotypically understood to be aromatic; therefore, the aromatic acid mayhave a unique trend based on unique interactions with the polarinterface.

Both NA14 and L-proline (cyclopentane-type structures) exhibit healingbehavior when tested for viscoelasticity and similar emulsion stabilitybehavior. Both cyclopentane-type structures stabilized emulsionscompared to 1% Na₂SO₄, and the emulsions with NA14 were some of the moststable. This indicates the impact of shear in emulsion formation, as theinitial droplets of the cyclopentane-type structures were apparentlystable as the change was minimal despite the interfacial healing thatNA14 and L-proline demonstrate.

NAmix1 shows behaviors exhibited by amphiphiles in that NAmix1 producesthe most stable/monodisperse emulsions on day 1, but shows the largestchange in a and increase in diameter on day 14. The increase in mediandiameter indicates increased coalescence, and the polydispersityincreases mobilization of fluids through the media. The time dependenceof fluid-fluid interactions is also evident, as destabilization effectsvaried with time. The NAmix1 shows the most extreme change in aqueousacid concentration, pH, and viscoelasticity, which may result from thevariety of species present in NAmix1. The decrease in viscoelasticity isaccompanied by behavior indicative of interfacial healing. Combining thehealing behavior with emulsion stability, it is believed that NA10 andNA14, or at least similar structural classes, are present and acting inthe NAmix1. The behaviors observed by NA18 seem to plateau when theacids present form aggregated species. If a lower concentration, such asNAmix1 in an aggregated state at 1 wt %, can elicit the sameviscoelastic and emulsion destabilizing response, it is believed that aless corrosive environment can be utilized to increase recovery factor.

The viscoelasticity data suggests that NA14 can increase coalescence andreduce snap-off. The TD-NMR data does not indicate that this increasecauses much of a change to the stability of the emulsions over timecompared to either NA18 or the low-salinity brine alone. The bridgeexperiments show the elastic nature of the interface formed between theoil and the NA14. NA14 delays snap-off compared to the low-salinitybrine, enabling more oil to be transferred through the bridge beforefailure. NA14 also reaches a CND near zero, confirming the strength ofthe interface.

NA18 is readily soluble in water, but that did not prevent it fromhalving the elasticity values of 1% Na₂SO₄. While acids typically dropthe viscoelasticity of interfaces, this is often linked to decreasingthe oil recovery. In this instance, the inventors have unexpectedlyfound that NA18 delayed bridge failure the longest, even though thebehavior is not classically elastic as observed for NA14. This isunexpected because there was not a 1:1 correlation. The bridge for theNA18 in oil system shows evidence of an interfacial film, strengtheningthe bridge, and further delaying snap-off, allowing even more oil to beremoved before failure. The film for the NA18 in oil system is believedto display plastic behavior, in that the bridge shows rigid behaviorunder conditions of low disturbance but more viscous behavior underhigher stress conditions.

NA10 shows viscoelasticity behavior between NA18 and the low-salinitybrine, which results in an unstable emulsion. NA18 was resistant tocoalescence. If the resistance to coalescence could be linked toincreased snap-off, that may explain the emulsion destabilization ofNA10.

Combinations of acids can also be used both to maintain connectivity butalso to reconnect ganglia after recovery has plateaued. That is, someacids can be used to delay snap-off/maintain connectivity and mobilityas long as possible, and some (e.g., the cyclopentane type) could workto re-establish connectivity once it has been lost, as suggested by thereparative tendencies they have shown in the ARG2/viscoelasticityresults.

Other non-limiting aspects and/or embodiments of the present disclosurecan include:

A1. A hydrocarbon recovery material, comprising an organic acid and awater material.

A2. The hydrocarbon recovery material of paragraph A1, wherein theorganic acid comprises a naphthenic acid.

A3. The hydrocarbon recovery material of paragraph A1 or paragraph A2,wherein the organic acid comprises cyclopentane carboxylic acid,L-proline, cyclohexane carboxylic acid, 3-cyclohexane propionic acid,p-toluic acid, a naphthenic acid, or a combination thereof.

A4. The hydrocarbon recovery material of any of paragraphs A1-A3,wherein the organic acid is selected from the group consisting ofcyclopentane carboxylic acid, cyclohexane carboxylic acid, 3-cyclohexanepropionic acid, and a combination thereof.

A5. The hydrocarbon recovery material of any of paragraphs A1-A4,wherein a concentration of the organic acid is about 10 mM or less.

A6. The hydrocarbon recovery material of any of paragraphs A1-A5,wherein a concentration of the organic acid is about 2 mM or less.

A7. The hydrocarbon recovery material of any of paragraphs A1-A6,wherein the water material has a salinity of about 100,000 ppm or less.

A8. The hydrocarbon recovery material of any of paragraphs A1-A6,wherein the water material has a salinity of from about 5,000 ppm toabout 100,000 ppm.

A9. The hydrocarbon recovery material of any of paragraphs A1-A6,wherein the water material has a salinity of from about 500 ppm to about5,000 ppm.

A10. The hydrocarbon recovery material of any of paragraphs A1-A6,wherein the water material is a smart water.

A11. The hydrocarbon recovery material of paragraph A10, wherein thewater material has a salinity of from about 40,000 ppm to about 200,000ppm.

A12. The hydrocarbon recovery material of any of paragraphs A1-A6,wherein the water material is a sulfate-enriched water, a calciumenriched water.

B1. An oil recovery method, comprising injecting a treatment fluid intoa reservoir under reservoir conditions, the reservoir containinghydrocarbons.

B2. The method of paragraph B1, further comprising mixing an organicacid and a water material to form a treatment fluid.

B3. The method of paragraph B1 or paragraph B2, wherein the treatmentfluid comprises the hydrocarbon recovery material of any of paragraphsA1-A12.

B4. The method of any of paragraphs B1-B3, wherein the reservoirconditions include a temperature of the reservoir of from about 10° C.to about 250° C.

B5. The method of any of paragraphs B1-B4, wherein the reservoirconditions include a temperature of the reservoir of from about 15° C.to about 150° C.

B6. The method of any of paragraphs B1-B5, wherein the reservoirconditions include a temperature of the reservoir of from about 20° C.to about 120° C.

B7. The method of any of paragraphs B1-B6, wherein the reservoirconditions include a pressure of the reservoir of from about 0 psi toabout 15,000 psi.

B8. The method of any of paragraphs B1-B7, wherein the reservoirconditions include a pressure of the reservoir of from about 300 psi toabout 10,000 psi.

B9. The method of any of paragraphs B1-B8, further comprising removinghydrocarbons from the reservoir.

C1. An oil recovery method, comprising injecting a treatment fluid intoa reservoir containing hydrocarbons, the treatment fluid comprising anorganic acid in one or more of an oil-in-water emulsion, a resindispersion, or a polymer capsule.

C2. The method of paragraph C1, further comprising encapsulating theorganic acid in one or more of the oil-in-water emulsion, the resindispersion, or the polymer capsule.

C3. The method of paragraph C1 or paragraph C2, wherein the organic acidcomprises a naphthenic acid.

C4. The method of any of paragraphs C1-C3, wherein the organic acidcomprises cyclopentane carboxylic acid, L-proline, cyclohexanecarboxylic acid, 3-cyclohexane propionic acid, p-toluic acid, anaphthenic acid, or a combination thereof.

C5. The method of any of paragraphs C1-C4, wherein the organic acid isselected from the group consisting of cyclopentane carboxylic acid,cyclohexane carboxylic acid, 3-cyclohexane propionic acid, and acombination thereof.

C6. The method of any of paragraphs C1-05, wherein a concentration ofthe organic acid in the treatment fluid is about 10 mM or less.

C7. The method of any of paragraphs C1-C6, wherein a concentration ofthe organic acid in the treatment fluid is about 2 mM or less.

C8. The method of any of paragraphs C1-C7, wherein the injection isperformed under reservoir conditions, the reservoir conditionscomprising a temperature of the reservoir of from about 10° C. to about250° C. and a pressure of the reservoir of from about 0 psi to about15,000 psi.

C9. The method of C8, wherein the reservoir conditions include atemperature of the reservoir of from about 10° C. to about 250° C.

C10. The method of paragraph C8 or paragraph C9, wherein the reservoirconditions include a temperature of the reservoir of from about 15° C.to about 150° C.

C11. The method of any of paragraphs C8-C10, wherein the reservoirconditions include a temperature of the reservoir of from about 20° C.to about 120° C.

C12. The method of any of paragraphs C8-C11, wherein the reservoirconditions include a pressure of the reservoir of from about 0 psi toabout 15,000 psi.

C13. The method of any of paragraphs C8-C12, wherein the reservoirconditions include a pressure of the reservoir of from about 300 psi toabout 10,000 psi.

C14. The method of any of paragraphs C1-C13, further comprising removinghydrocarbons from the reservoir.

C15. The method of any of paragraphs C2-C14, wherein encapsulating theorganic acid in the oil-in-water emulsion comprises adding the organicacid to an oil to form a mixture; and adding the treatment fluid to themixture to form an oil-in-water emulsion.

C16. The method of any of paragraphs C2-C15, wherein encapsulating theorganic acid in the resin dispersion comprises adding the organic acidto a resin to form resin dispersion.

C17. The method of any of paragraphs C2-C16, wherein encapsulating theorganic acid in the polymer capsule comprises adding the organic acid toa polymer and a crosslinker to form a polymer capsule.

C18. The method of paragraph C1-C17, wherein the treatment fluid furthercomprises a water material.

C19. The method of any of paragraphs C16-C18, further comprising addingthe resin dispersion, the polymer capsule, or a combination thereof tothe water material to form the treatment fluid.

C20. The method of any of paragraphs C1-C19, wherein the water materialhas a salinity of about 100,000 ppm or less.

C21. The hydrocarbon recovery material of any of paragraphs C1-C20,wherein the water material has a salinity of from about 5,000 ppm toabout 100,000 ppm.

C22. The hydrocarbon recovery material of any of paragraphs C1-C21,wherein the water material has a salinity of from about 500 ppm to about5,000 ppm.

C23. The hydrocarbon recovery material of any of paragraphs C1-C22,wherein the water material is a smart water.

C24. The hydrocarbon recovery material of paragraph C23, wherein thewater material (e.g., the smart water) has a salinity of from about40,000 ppm to about 200,000 ppm.

C25. The hydrocarbon recovery material of any of paragraphs C1-C24,wherein the water material is a sulfate-enriched water, a calciumenriched water.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, within a range includes everypoint or individual value between its end points even though notexplicitly recited. Thus, every point or individual value may serve asits own lower or upper limit combined with any other point or individualvalue or any other lower or upper limit, to recite a range notexplicitly recited.

The phrases, unless otherwise specified, “consists essentially of” and“consisting essentially of” do not exclude the presence of other steps,elements, or materials, whether or not, specifically mentioned in thisspecification, so long as such steps, elements, or materials, do notaffect the basic and novel characteristics of the present disclosure,additionally, they do not exclude impurities and variances normallyassociated with the elements and materials used.

All documents described herein are incorporated by reference herein,including any priority documents and/or testing procedures to the extentthey are not inconsistent with this text. As is apparent from theforegoing general description and the specific embodiments, while formsof this disclosure have been illustrated and described, variousmodifications can be made without departing from the spirit and scope ofthis disclosure. Accordingly, it is not intended that this disclosure belimited thereby. Likewise, the term “comprising” is consideredsynonymous with the term “including” for purposes of United States law.Likewise whenever a composition, an element or a group of elements ispreceded with the transitional phrase “comprising,” it is understoodthat we also contemplate the same composition or group of elements withtransitional phrases “consisting essentially of,” “consisting of,”“selected from the group of consisting of,” or “is” preceding therecitation of the composition, element, or elements and vice versa.

While this disclosure has been described with respect to a number ofembodiments and examples, those skilled in the art, having benefit ofthis disclosure, will appreciate that other embodiments can be devisedwhich do not depart from the scope and spirit of this disclosure.

What is claimed is:
 1. An oil recovery method, comprising: injecting awaterflooding treatment fluid into a reservoir containing hydrocarbons,the waterflooding treatment fluid comprising an organic acid in a resindispersion, the waterflooding treatment fluid further comprising water,the organic acid comprising one or more naphthenic acids; and producinghydrocarbons from the reservoir.
 2. The method of claim 1, furthercomprising encapsulating the organic acid in the resin dispersion toform the waterflooding treatment fluid.
 3. The method of claim 1,wherein a concentration of the organic acid in the waterfloodingtreatment fluid is about 10 mM or less.
 4. The method of claim 1,wherein the organic acid comprises one or more cycloalkane carboxylicacids.
 5. The method of claim 1, further comprising dispersing the resindispersion in the water.
 6. The method of claim 1, wherein aconcentration of the organic acid in the resin dispersion is about10,000 mM or less.
 7. The method of claim 6, wherein the concentrationof the organic acid in the resin dispersion is about 1,000 mM or less.8. The method of claim 7, wherein the water has a salinity of about100,000 ppm or less.
 9. The method of claim 1, wherein the one or morenaphthenic acids comprises:

or a combination thereof.
 10. An oil recovery method, comprising:injecting a treatment fluid into a reservoir containing hydrocarbons,the treatment fluid comprising one or more naphthenic acids in a resindispersion, the treatment fluid further comprising water, the treatmentfluid injected at a pressure below a fracturing pressure; and producinghydrocarbons from the reservoir.
 11. The method of claim 10, wherein theone or more naphthenic acids comprises:

or a combination thereof.
 12. The method of claim 10, wherein aconcentration of the one or more naphthenic acids in the treatment fluidis about 10 mM or less.
 13. The method of claim 10, wherein aconcentration of the one or more naphthenic acids in the treatment fluidis about 2 mM or less.
 14. The method of claim 10, further comprisingdispersing the resin dispersion in the water.
 15. The method of claim10, wherein a concentration of the one or more naphthenic acids in theresin dispersion is about 10,000 mM or less.
 16. The method of claim 15,wherein the concentration of the one or more naphthenic acids in theresin dispersion is about 1,000 mM or less.
 17. The method of claim 16,wherein the water has a salinity of about 100,000 ppm or less.
 18. Anoil recovery method, comprising: injecting a treatment fluid into areservoir containing hydrocarbons to stimulate production from thereservoir, the treatment fluid comprising one or more naphthenic acidsin a resin dispersion, the treatment fluid further comprising water andthe one or more naphthenic acids comprising:

or a combination thereof; and producing hydrocarbons from the reservoir.19. An oil recovery method, comprising: injecting a waterfloodingtreatment fluid into a reservoir containing hydrocarbons, thewaterflooding treatment fluid comprising an organic acid in a resindispersion, the waterflooding treatment fluid further comprising water,the organic acid comprising one or more cycloalkane carboxylic acids;and producing hydrocarbons from the reservoir.
 20. An oil recoverymethod, comprising: injecting a waterflooding treatment fluid into areservoir containing hydrocarbons, the waterflooding treatment fluidcomprising an organic acid in a resin dispersion, the waterfloodingtreatment fluid further comprising water, the organic acid comprisingone or more naphthenic acids, the one or more naphthenic acidscomprising:

or a combination thereof; and producing hydrocarbons from the reservoir.